Very large electrical power infrastructure distribution transformers, such as those used in facilities known as substations, use three-phase power at substantial voltages and currents, typically lowering the voltage drawn from long distance transmission lines and providing power to large customers—factories, apartment buildings, housing developments, and the like—which are in turn located in the vicinity of the substations. Comparable transformers are used at power plants and other facilities to step up voltage to levels suitable for application to long distance transmission lines.
Load current variations in power distribution systems affect voltage drops across both customer load impedances and distribution system elements. These voltage changes require compensating adjustments in transformer winding connections (“taps”) to maintain the available voltage at the loads within prescribed limits, with the intent of maintaining as close to a constant voltage as practicable at each distributed load. It is known in power distribution apparatus to include, with the requisite multi-tap power transformers, automatically controlled load tap changers (LTCs) that can adjust the voltage at which power is fed to large loads, typically several times per day but as often as hundreds of times per day. The tap changes are made without interrupting the load current in some embodiments, hence the term “load tap changer”.
Despite typical use of make-before-break switching, voltage and current transients can cause arcing (voltage transients sufficient to cause gas bubbles and ionization in a liquid fill fluid) and local heating events, particularly at the LTC contacts. These events can promote changes in the refined petroleum distillates (mineral oils) commonly used in such applications, including fragmentation that releases volatiles (short-chain hydrocarbon gases), oxidation that forms acids and insoluble particulates, and a variety of other processes yielding mixed products that are preferably but imperfectly filtered and vented out of the LTCs.
In high current contact applications such as load tap changers, circuit breakers, unloaded (de-energized switching) tap changers, and other bolted, sliding, and pressure-impelled connections, it is desirable in view of safety, damage, and overall cost considerations that the physical condition of the contact hardware and fill fluid be monitored effectively continuously. Such monitoring can potentially maximize overall power distribution system reliability.
Electrical contacts in oil (or another insulating fluid) are susceptible to film formation, which can lead to increased contact resistance. Over time, the higher contact resistance increases voltage drop and thus contact temperature, with the possibility of the formation of “coke” (a hard carbonaceous material with poor conductivity that also acts as a thermal insulator). The positive feedback cycle of more heat forming a thicker coke layer can increase local temperatures abruptly and severely. This runaway temperature increase can in turn lead to abrupt failure of a contact system.
Film buildup is accelerated by the presence of contaminants and other undesirable chemicals in the fluid. Electrical stress in the area of the electrical contact is thought to contribute directly to the formation of impurities. In order to reduce the potential impact of film formation and coking, it would be helpful to be able to predict contact degradation early, so that corrective action could be taken before the contact system is irreversibly damaged.
In the known prior art, detection is limited to measurement of contact resistance, analysis of vented and dissolved gases, temperature difference between oil in the LTC and oil in the associated transformer, and visual inspection. Problems potentially detectable by measurements of contact resistance may be masked by the existence of alternative conduction paths and of resistance in other parts of a system. Systems typically must be deenergized for resistance tests. Gas analysis and observation of temperature differential measure only the consequences of contact heating, not the condition of the contacts themselves. Conditions within an LTC or other power switchgear device not related to contact degradation can produce false positive readings. Such test defects can lead to costly and unnecessary maintenance, leading in turn to administrative distrust of testing processes and less-than-effective test application. Also, such tests do not constitute continuous monitoring.
Visual inspection requires that a system with a suspect LTC or other switchgear device be de-energized, then in many cases drained of oil and disassembled. The constituent parts must then be visually examined (sometimes microscopically). Such evaluation is therefore typically performed only when opportunity—and extrinsic evidence—justify the effort and the inevitable loss of continuous service to a load.
Accordingly, it is desirable to provide an apparatus and method that allow timely, accurate, non-invasive detection of degradation of contact condition in power switchgear.